1. Issue Summary
On Nov. 19, 2020, the Federal Energy Regulatory Commission (Commission or FERC) issued a notice of proposed rulemaking (NOPR) to improve the accuracy and transparency of transmission line ratings.  These ratings represent the maximum transfer capability of each transmission line and rely on scrutiny only to prevent overrating, subject to reliability criteria. This simplified rating mechanism relies on rare, single condition expectations for when maximum capability is needed, but does not reflect the actual capacity of a line under the vast majority of conditions. As such, transmission line ratings are chronically understated.
Understated line ratings can result in major underutilization of infrastructure resulting in unnecessarily increased transmission congestion and generation costs. This also leads to underutilization of generation in export-constrained locales, which are disproportionately zero-emission resources given their greater geographic constraints.
The proposal would require transmission providers (TPs) to implement ambient-adjusted ratings (AARs); regional transmission organization and independent system operators (RTO/ISOs) to establish and implement necessary systems and procedures to allow transmission owners (TOs) to update line ratings at least hourly; and TOs to share line ratings and methodologies with their respective transmission providers and market monitors, where applicable.
These comments provide the overarching view of the R Street Institute (RSI), including a strategic take on next steps for the Commission. They also provide responses to some of the specific questions posed by the Commission.
2. Summary of R Street Position
The R Street Institute applauds the Commission for examining this issue. The problem statement is sound; line ratings are chronically underreported as they do not reflect fluctuating weather conditions that alter the near-term transfer capability of the transmission system. Independent market monitors consistently argue for the need for more transparent and accurate line ratings practices, as doing so would result in over $100 million in cost savings in some individual RTO/ISOs.  The Commission is also correct in taking a more hands-on approach to economic regulation, given the perverse asset management incentives under the cost-of-service paradigm.
In a competitive marketplace, requiring a uniform practice that suppliers had not widely enacted would likely reduce economic efficiency. But the Commission is justified using such tools for entities under cost-of-service regulation, which creates a disincentive for efficient asset management. Under cost-of-service, the role of the regulator is to substitute for the economic discipline that would otherwise exist in a competitive context.  However, transmission line ratings are only subject to reliability standards review and, as such, there is no economic oversight mechanism. Given the incentive to add to rate base in lieu of using the existing system efficiently, industrial consumers note that the current arrangement results in systemic incentives and pervasive opportunities for understating line ratings, and transmission system capacity results in “proposals for new construction and additions to transmission rate base that could be avoided if ratings were required to be calibrated to optimize the existing system.” 
Given the absence of competition and corrective economic oversight, the Commission should pursue enabling an independent authority to scrutinize line ratings consistent with economic criteria. Without such ambition, the Commission must resort to more blunt policy tools like standards. Since AARs constitute a minimum best practice, requiring their application ubiquitously is prudent, as the NOPR proposes. But it falls well short of economical dynamic line ratings (DLRs).
The Commission should require the use of DLRs as a default position and permit exemptions where justified on grounds of cost-benefit analysis. One option is a phased-in approach that prioritizes the most accurate, situationally reflective ratings for chronically congested lines. It is also possible to pursue varying gradients of DLRs; for example, it may be cost-beneficial to pursue wind and solar irradiance adjusted ratings but not for cloud cover and precipitation. Even simplistic approaches, such as treating solar irradiance in a binary fashion reflecting sunrise and sunset, could yield low-cost practices with appreciable benefits.
Similar to ubiquitous AARs, the Commission should require unique emergency ratings. The Commission should set a high default bar for emergency ratings and provide the option for less stringent practices if the TO or RTO/ISO can demonstrate a verifiable reliability concern or public health concern from a qualified authority. The record is unfortunately sparse on emergency ratings, but the Commission should not let that deter the pursuit of improving their accuracy and transparency.
The proposal for TOs to share line ratings and methodologies with their respective transmission providers and market monitors is an improvement, but overall the NOPR is insufficient on transparency. Ideally, line ratings values, methods and associated assumptions and calculations should be available to the broader set of market participants and state commissions as well. There is no problem with this where it is already implemented. For example, PJM already posts ratings on its website in 15 minute intervals and its independent market monitor (IMM) continues to call for all ratings to be made public. Failure to do so may undermine implementation of the AAR provision of the NOPR, exacerbate information asymmetries between market participants and erect barriers to new transmission entrants.
Overall, the Commission should be cautious about pursuing asymmetric treatment within and outside of RTO/ISOs. Imposing stricter requirements on TOs within RTO/ISOs can deter RTO/ISO membership, considering that RTO/ISO participation is voluntary with TOs as the deciding industry stakeholder group.
3. Responses to Commission Questions
Should transmission line ratings and transmission line rating methodologies be shared with other transmission providers, upon request? Whether to require transmission owners to make their transmission line ratings and rating methodologies available to other interested stakeholders, including posting information on their OASIS pages or other password protected online forum. (P7, 129)
Ideally, line ratings values, methods, and associated assumptions and calculations should be available to the broader set of market participants and state commissions as well. Additional transparency is key to accomplish what the NOPR already proposes. For example, the independent market monitor for Midcontinent ISO (MISO) said “[a]dditional transparency regarding rating methodologies is essential for administering an AAR requirement.”  The more dynamic line ratings become, the more important their values and methods become to any physical or financial market participant affected by transmission congestion.
At minimum, line ratings and the methodology used to determine the ratings should be freely shared within the protected circle of transmission providers, ISO/RTOs and market monitors at minimum. There should be an explicit requirement to identify and justify different ratings being used by separate transmission owners, for separate segments of the same physical circuit. The FERC should also require all TPs to submit a list of most frequently and significantly constrained transmission facilities (lines and transformers) annually. For each facility on the list, the TP should provide the range of emergency and base case ratings or explain why there is no range.
Without sufficient transparency, greater and less predictable fluctuations in line ratings could introduce artificial risk for congestion management products, especially financial transmission rights. Further, enabling TOs to alter line ratings without visibility for other market participants would create an information asymmetry that could lead to anti-competitive conduct. Many TOs also own generation and hold financial markets positions that could leverage their information advantage in ways that extract rents and reduce economic efficiency, such as selective line ratings adjustment to favor their own generation. As for financial products, adjustments in line ratings could quickly and profoundly shift shadow prices across numerous transmission constraints, materially affecting financial holdings and creating opportunities for cross-product manipulation.
Some TOs make line ratings and their methodologies public already, and this has not provided any evidence of problems. For example, PJM posts ratings every 15 minutes on its website and publishes guidelines for TOs. The independent market monitor for PJM contends that “[a]ll line rating changes and the detailed reasons for those change should be public and fully transparent.” 
Considering the broader application of grid-enhancing technologies, including but not limited to line ratings, transparency is imperative for competitive suppliers to evaluate market valuations of prospective investments. Transparency is truly needed to capture the spirit of “open access”, and the Commission should err on the side of sunshine.
Should the use of unique emergency ratings be considered as a factor in a determination of just and reasonable? (P46)
Yes. The NOPR answers this itself in stating that “[i]naccurate transmission line ratings may result in Commission-jurisdictional rates that are unjust and unreasonable.”  Inaccurate ratings of all kinds are not just and reasonable; emergency ratings should not get a pass.
Should transmission providers outside of RTO/ISO markets be required to implement systems and procedures to update ratings at least hourly? (P82)
Generally, transmission management inefficiency and the opacity of line ratings outside RTO/ISOs is far greater than the deficiencies within them. Updating ratings hourly would be a prudent start.
Should transmission providers be required to implement DLRs across their systems or on certain transmission lines that have the most to benefit from a dynamic rating? (P100)
The Commission should require the use of dynamic line ratings (DLRs) as a default position, and permit exemptions where justified on grounds of cost-benefit analysis. One option is a phased-in approach that prioritizes the most accurate, situationally reflective ratings for chronically congested lines.
Should transmission providers that operate outside an RTO/ISO be required to implement AAR? (P109)
AARs and unique emergency ratings, at minimum, should be universal for all TPs, regardless of their participation in an ISO/RTO. The Commission should be mindful of the side effects of imposing stricter requirements on TOs in RTO/ISOs than those outside RTO/ISOs. That is, TOs are the dominate industry stakeholder group that determines RTO/ISO membership and thus RTO/ISO footprints in part reflect the net value proposition of RTO/ISO membership to TOs.
Should RTOs/ISOs be required to conduct a one-time study of the cost effectiveness of DLR implementation? If so, what should the details or format be of such a study? (P110)
A one-time study is no substitute for ongoing economic scrutiny of transmission line ratings. Requiring ISO/RTOs to perform a cost benefit study on DLRs may have insight but offer limited ongoing value. Such “snapshot in time” analyses do not age well. Rather, cost-benefit analysis (CBA) should be used as an exemption tool, rather than as a gatekeeper, for DLRs. Such CBA should look out at least 10 years and consider a wide range of possible generation dispatch scenarios.
CBA should consider that the costs and benefits of DLR may vary by its individual components. For example, wind and solar irradiance intensity are easier to implement with larger benefits than some other forms of weather conditions or transmission line conditions. At an even more granular level, a simplistic and certainly cost-effective approach to solar irradiance could simply boil down to diurnal cycles, where ratings change based on sunrise and sunset patterns.
CBA should not only account for operating benefits, but for capital cost savings. Commercially available DLR systems can be installed at a fraction the cost of conventional line enhancements.  Since operations-centric applications will not capture this, the benefit of DLRs should be incorporated in transmission expansion planning processes.
To what degree should transmission providers be required to use unique emergency ratings? To what degree are transmission providers already using unique emergency ratings and what are the durations most commonly used? (P111)
Unique emergency ratings should be the minimum regulatory expectation. Documentation of all ratings, including emergency ratings, should be universal for all TOs, regardless of their participation in an ISO/RTO. The Commission should set a high default bar for emergency ratings and provide the option for less stringent practices if the TO or RTO/ISO can demonstrate a verifiable reliability concern or public health concern from a qualified authority. On the latter, for example, California authorities may seek to avoid line sag as a wildfire prevention tool, which may require lower emergency ratings than the physical constraints of the line would otherwise justify.
Emergency ratings are sometimes used implicitly during emergency conditions. For example, the August 2003 blackout saw system operators exceed circuits at 103 percent, and informal communication suggested operators exceeded that level before. This also raises the point that implementing emergency ratings may be prone to more system operator errors with potential reliability implications.  Reliability opt-outs akin to those in the pro forma Open Access Transmission Tariff could provide a “safety valve” mechanism, but must be scrutinized to ensure only legitimate reliability concerns apply.
As for the duration of current emergency ratings, current practices appear to vary substantially. Some TOs apply 30-minute periods, while some RTO/ISO systems examine two to four hours.  PJM already uses four hours for long-term emergency line ratings applied to contingency constraints. 
The record is unfortunately sparse on emergency ratings, but the Commission should not let that deter the pursuit of improving their accuracy and transparency. The Commission could seek to motivate additional research and prompt a stronger record, such as engaging the Institute of Electrical and Electronics Engineers, on the matter.
What are the costs and benefits associated with requiring the use of emergency ratings? (P112)
Generally speaking, the costs are minimal while the benefits are large. Previous analyses by Potomac Economics suggest emergency ratings are a key driver of production cost savings (benefits) from improvement. However, the benefits are larger than this. Emergency ratings can avoid customer outages, and thus the avoided value of lost load could be an applicable metric unique to benefits calculations for emergency ratings.
Although the process of unique emergency ratings process may have minimal costs, its implementation could increase wear and tear on transmission infrastructure. However, such evaluations must account for the frequency and duration of uses, which are typically very brief and uncommon, in calculating the increased fixed operating and maintenance costs or asset depreciation from shortening its lifespan, where the time value of replacement costs come into play. Any costs might vary by the age and type of transmission line; those nearing their end of life may have a different cost profile than newer vintage lines.
RSI respectfully requests the Commission consider the comments contained herein.
/s/ Devin Hartman
Director, Energy and Environmental Policy
/s/ Beth Garza
Senior Fellow, Energy
R Street Institute
1212 New York Ave. NW, Suite 900
Washington, D.C. 20005
[email protected] 
March 22, 2021
  See e.g., Potomac Economics, “2018 State of the Market Report for the MISO Electricity Markets,” Independent Market Monitor for the Midcontinent ISO, June 2019, p. viii. https://www.potomaceconomics.com/wp-content/uploads/2019/06/2018-MISO-SOM_Report_Final2.pdf .
  See e.g., Devin Hartman, “Wholesale Electricity Markets in the Technological Age,” R Street Policy Study, No. 67, August 2016, p. 15. https://www.rstreet.org/wp-content/uploads/2016/08/67.pdf .
  Comments of the Electricity Consumers Resource Council, the PJM Industrial Customer Coalition, and the Coalition of MISO Transmission Customers on ‘Managing Transmission Line Ratings’ to the Federal Energy Regulatory Commission, Docket No. AD19-15-000, Nov. 1, 2019, pp. 5-6. https://elibrary.ferc.gov/eLibrary/filelist?document_id=14811397&optimized=false .
  Michael Chiasson, “Transparency of Transmission Line Rating Methodologies,” FERC Technical Conference on Managing Line Ratings: AD19-15 Panel 5, Sept. 11, 2019, p. 2. https://elibrary.ferc.gov/eLibrary/filelist?document_id=14799954&optimized=false .
  “Post-technical Conference Comments of the Independent Market Monitor for PJM on ‘Managing Transmission Line Ratings’ to the Federal Energy Regulatory Commission, Docket No. AD19-15-000, Nov. 4, 2019, p. 5. https://www.monitoringanalytics.com/Filings/2019/IMM_Post_Tech_Conf_Comments_Docket_No_AD19-15_20191104.pdf .
  See e.g., Tapani O. Seppa, “Reliability and real time transmission line ratings,” The Valley Group – A Nexans Company, June 18, 2007, p. 2. https://www.nexans.com/US/2009/Reliability%20and%20real%20time%20transmission%20line%20ratings.pdf .
  Ibid, p. 5.
  Potomac Economics, “2018 State of the Market Report for the MISO Electricity Markets,” p. 57. https://www.potomaceconomics.com/wp-content/uploads/2019/06/2018-MISO-SOM_Report_Final2.pdf .
  “Post-technical Conference Comments of the Independent Market Monitor for PJM,” p. 3. https://www.monitoringanalytics.com/Filings/2019/IMM_Post_Tech_Conf_Comments_Docket_No_AD19-15_20191104.pdf .
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